In this document, unless the context otherwise requires, the following terms shall have the meaning set out below.

American depositary receipt.

American depositary share.

Annual general meeting.

The former Amoco Corporation and its subsidiaries.

Atlantic Richfield Company and its subsidiaries.

An entity, including an unincorporated entity such as a partnership, over which the group has significant influence and that is neither a subsidiary nor a joint venture. Significant influence is the power to participate in the financial and operating policy decisions of an entity but is not control or joint control over those policies.

42 US gallons.

barrels per day.

barrels of oil equivalent.

BP p.l.c. and its subsidiaries.

Burmah Castrol PLC and its subsidiaries.

One-hundredth of the US dollar.

BP p.l.c.

The US dollar.

European Union.

Natural gas.

Crude oil and natural gas.

International Financial Reporting

Standards.

Joint control is the contractually agreed sharing of control over an economic activity, and exists only when the strategic financial and operating decisions relating to the activity require the unanimous consent of the parties sharing control (the venturers).

A contractual arrangement whereby two or more parties undertake an economic activity that is subject to joint control.

A joint venture where the venturers jointly control, and often have a direct ownership interest in the assets of the venture. The assets are used to obtain benefits for the venturers. Each venturer may take a share of the output from the assets and each bears an agreed share of the expenses incurred.

A joint venture that involves the establishment of a corporation, partnership or other entity in which each venturer has an interest. A contractual arrangement between the venturers establishes joint control over the economic activity of the entity.

Crude oil, condensate and natural gas liquids.

Liquefied natural gas.

London Stock Exchange plc.

Liquefied petroleum gas.

thousand barrels per day.

thousand barrels of oil equivalent per day.

million British thermal units.

million barrels of oil equivalent.

million cubic feet.

million cubic feet per day.

Methyl tertiary butyl ether.

Megawatt.

Natural gas liquids.

Organization of Petroleum Exporting Countries.

Ordinary fully paid shares in BP p.l.c. of 25c each.

One-hundredth of a pound sterling.

The pound sterling.

Cumulative First Preference Shares and Cumulative Second Preference Shares in BP p.l.c. of £1 each.

A production-sharing agreement (PSA) is an arrangement through which an oil company bears the risks and costs of exploration, development and production. In return, if exploration is successful, the oil company receives entitlement to variable physical volumes of hydrocarbons, representing recovery of the costs incurred and a stipulated share of the production remaining after such cost recovery.

The United States Securities and Exchange Commission.

An entity that is controlled by the BP group. Control is the power to govern the financial and operating policies of an entity so as to obtain the benefits from its activities.

2,204.6 pounds.

United Kingdom of Great Britain and Northern Ireland.

United States of America.

 

Contents

 

Business review

 

Group overview

 

Our organization

BP is one of the world’s leading international oil and gas companies^a. We operate in more than 80 countries, providing our customers with fuel for transportation, energy for heat and light, retail services and petrochemicals products for everyday items.

As a global group, our interests and activities are held or operated through subsidiaries, jointly controlled entities or associates established in – and subject to the laws and regulations of – many different jurisdictions. These interests and activities covered two business segments in 2009: Exploration and Production and Refining and Marketing. BP’s activities in low-carbon energy are managed through our Alternative Energy business, which is reported within Other businesses and corporate.

          Exploration and Production’s activities cover three key areas. Upstream activities include oil and natural gas exploration, field development and production. Midstream activities include pipeline, transportation and processing activities related to our upstream activities. Marketing and trading activities include the marketing and trading of natural gas, including liquefied natural gas (LNG), together with power and natural gas liquids (NGLs).

          Refining and Marketing’s activities include the supply and trading, refining, manufacturing, marketing and transportation of crude oil, petroleum and petrochemicals products and related services.

          The two business segments each comprise a number of strategic performance units (SPUs), which are organized along either geographic or activity-related lines. The role of the SPU includes the development of local capability and the fostering of external stakeholder relationships. Each SPU is of a scale that allows for a close focus on performance delivery by its respective segment, which includes the appropriate management of costs.

Our group functions and regions support the work of our segments and businesses. Their key objectives are to establish and monitor fit-for-purpose functional standards across the group; to act as centres of deep functional expertise; to access significant leverage with third-party suppliers; and to establish and maintain capabilities among the functional staff employed within our operating businesses. In addition, the head of each region provides the required integration and co-ordination of group activities in a particular geographic area and represents BP to external parties.

Where we operate

BP’s worldwide headquarters is in London. The UK is a centre for trading, legal, finance and other business functions as well as three of BP’s major global research and technology groups.

          We have well-established operations in Europe, the US, Canada, Russia, South America, Australasia, Asia and parts of Africa. Currently, around 67% of the group’s capital is invested in Organisation for Economic Co-operation and Development (OECD) countries, with around 40% of our fixed assets located in the US and around 20% in Europe.

 

Our Exploration and Production segment conducts upstream and midstream activities in 30 countries and we are the largest producer of oil and gas in North America. The segment’s geographical coverage in these activities currently includes Angola, Azerbaijan, Canada, Egypt, Russia, Trinidad & Tobago (Trinidad), Norway, the UK, the US and locations within Asia Pacific, Latin America, North Africa and the Middle East. Our Exploration and Production segment also includes gas marketing and trading activities, primarily in Canada, Europe and the US. In Russia, we have an important associate through our 50% shareholding in TNK-BP, a major oil company with exploration assets, refineries and other downstream infrastructure.

          In Refining and Marketing, we market our products in more than 80 countries, with a particularly strong presence in the US and Europe, as well as major activities in Australia, Southern Africa, India and China. In the US, we own or have a share in five refineries and market primarily under the Amoco, ARCO, BP and Castrol brands. We are one of the largest gasoline retailers in that country. In Europe, we own or have a share in seven refineries and we market extensively across the region, primarily under the Aral, BP and Castrol brands. Our long-established supply and trading activity is responsible for delivering value across the crude and oil products supply chain. Our petrochemicals business maintains a manufacturing position globally, with an emphasis on growth in Asia. We continue to seek opportunities to broaden our activities in growth markets such as China and India.

Our market

Energy markets remained volatile in 2009, reflecting the dramatic drop in world economic activity early in the year and indications of economic recovery in the second half. Looking ahead, the long-term outlook is one of growing demand for energy^a, particularly in Asia, alongside challenges for the industry in meeting this demand. Rising incomes and expanding urban populations are expected to drive demand, while the evolution towards a lower-carbon economy will require technology, innovation and investment.

World oil consumption declined for a second successive year during 2009, with growing demand in non-OECD countries once again more than offset by falling consumption in OECD countries. Average crude oil prices for 2009 were lower than in the previous year, breaking an unprecedented string of seven consecutive annual increases. Natural gas prices also weakened in 2009 and were highly volatile. Refining margins fell sharply as oil demand contracted and substantial amounts of new refining capacity came onstream.

Economic context

The world economy began to show signs of recovery in the latter part of 2009 and this is expected to continue through 2010, but economic growth in 2010 is likely to be muted in the OECD countries. Growth in global oil consumption is expected to resume as the world economy recovers from recession.

          In 2009, concerns about the volatility of commodity and financial markets, combined with renewed focus on climate change and the early experiences with efforts to reduce CO₂ emissions in the EU and elsewhere, led to an increased focus on the appropriate role for markets, government oversight and other policy measures relating to the supply and consumption of energy.

          The concept of peak oil – the time after which less oil is available to the world – continues to hold the interest of some commentators, although global proved reserves have tended to rise over time and remain sufficient to support higher levels of production. Meanwhile, the consumer response to higher prices and an increased focus on energy efficiency have served to constrain demand. We expect regulation and taxation of the energy industry and energy users to increase in many areas over the short to medium term.

Crude oil prices

Dated Brent for the year averaged $61.67 per barrel, about 37% below 2008’s record average of $97.26 per barrel. Prices began the year at their lowest point as the world economy grappled with the sharpest downturn in modern economic history.

          Global oil consumption reflected the economic slowdown, falling by roughly 1.3 million b/d for the year (1.5%)^b, the largest annual decline since 1982. The biggest reductions were early in the year, with OECD countries accounting for the entire global decline. Crude oil prices rose sharply in the second quarter in response to sustained OPEC production cuts and emerging signs of stabilization in the world economy, despite very high commercial oil inventories in the OECD. OPEC members sustained roughly 2.5 million b/d of production cuts^b implemented in late 2008 and throughout 2009. Additional price increases later in the year were sustained by further positive economic news and signs that the inventory overhang was beginning to correct.

          In 2008, the average dated Brent price of $97.26 per barrel was 34% higher than the $72.39 per barrel average seen in 2007. Daily prices began 2008 at $96.02 per barrel, peaked at $144.22 per barrel on 3 July 2008, and fell to $36.55 per barrel at the end of the year. The sharp drop in prices was due to falling demand in the second half of the year, caused by the OECD falling into recession and the lagged effect on demand of high prices in the first half of the year. OPEC had increased production significantly through the first three quarters and, as a result of falling consumption and rising OPEC production, inventories rose. As prices continued to decline, OPEC responded with successive announcements of production cuts in September, October and December.

          Looking ahead, in 2010 we expect oil price movements to continue to be driven by the extent of global economic growth and its resulting implications for oil consumption, and by OPEC production decisions.

Natural gas prices

Natural gas prices weakened in 2009 and were volatile. The average US Henry Hub First of Month Index fell to $3.99/mmBtu in 2009, a 56% decrease from the record $9.04/mmBtu average seen in 2008.

Recession-induced demand declines and strong production caused prices to drop from $6.16/mmBtu at the start of the year to $2.84/mmBtu in September. However, over the course of the year, the impact was partly offset as US regional gas price differentials narrowed, driven partly by the Rockies Express Pipeline extension allowing the transportation of larger quantities of gas out of the Rockies area. Reduced imports from Canada, slowing US production growth and cooler temperatures allowed prices to recover to $4.49/mmBtu by the end of the year. Prices at the UK National Balancing Point similarly fell to an average of 30.85 pence per therm, 47% below the 2008 average price of 58.12 pence per therm. In 2009, there was a switch of uncontracted LNG cargoes from Asia to Europe, reflecting a shift in relative spot prices. LNG imports to Europe have competed with pipeline imports, where the gas price is often indexed to oil prices, as well as with marginal European gas production. Gas prices were often at or below parity with coal, when translated into the cost of generating power, which led to gas displacing coal in power generation in Europe and the US.

          In 2008, average natural gas prices in the US and the UK were higher than in 2007. The Henry Hub First of Month Index, at $9.04/mmBtu, was 32% higher than the 2007 average of $6.86/mmBtu. 2008’s prices peaked at $13.11/mmBtu in July amid robust demand and falling US gas imports, but fell to $6.90/mmBtu in December as demand weakened and production remained strong. In the UK, 2008 average prices of 58.12 pence per therm at the National Balancing Point, were 94% above the 2007 average of 29.95 pence per therm.

          Looking ahead, gas markets in 2010 are expected to follow developments in the global economy, but any price movements are likely to be impacted by significant new LNG capacity as it becomes available.

Refining margins

Refining margins fell sharply in 2009 as demand for oil products reduced in the wake of the global economic recession and new refining capacity came onstream, mostly in Asia Pacific. The BP global indicator refining margin (GIM)^a averaged $4 per barrel last year, down $2.50 per barrel compared with 2008. Margins in the Far East were particularly badly hit –averaging close to zero in Singapore – because new refining capacity has been added in the region.

          Margins in Europe were about half the 2008 level as the reduction in economic activity meant weaker demand for commercial transport and therefore lower middle distillate consumption. In the US, where refining is more highly upgraded and the transport market more gasoline-orientated, margins were stronger than in Europe.

          Refining margins in 2008 were lower than in 2007, with the BP GIM decreasing to an average of $6.50 per barrel from $9.94 per barrel in 2007. The premium for light products above fuel oils remained high, reflecting a continuing shortage of upgrading capacity and the favouring of fully upgraded refineries over less complex sites.

          Looking ahead, refining margins are likely to remain under pressure through 2010, with capacity already exceeding demand and additional new capacity expected to come onstream during the year.

 

Long-term outlook

Recent economic conditions have weakened global demand for primary energy, but a number of forecasts predict a return to growth in the medium term. This is underpinned by continuing population growth and by generally rising living standards in the developing world, including the expansion of urban populations.

          Under the International Energy Agency’s (IEA) reference scenario, global energy demand is projected to increase by around 40% between 2007 and 2030^a. That scenario also projects that fossil fuels will still be satisfying as much as 80% of the world’s energy needs in 2030. At current rates of consumption, the world has enough proved reserves of fossil fuels to meet these requirements^b if investment is permitted to turn those reserves into production capacity. However, to meet the potential growth in demand, continued investment in new technology will be required in order to boost recovery from declining fields and commercialize currently inaccessible resources. For example, in oil alone, where we believe there are reserves in place to satisfy approximately 40 years’ demand at current rates of consumption^b, we estimate that our industry will need to bring nearly 50 million barrels per day of new capacity onstream by 2030 if it is to meet the increased demand. To play their part in achieving this, energy companies such as BP will need secure and reliable access to as-yet undeveloped resources. We estimate that more than 80% of the world’s oil resources are held by Russia, Mexico and members of OPEC – areas where international oil companies are frequently limited or prohibited from applying their technology and expertise to produce additional supply. New partnerships will be required to transform latent resources into much-needed proved reserves.

          A more diverse mix of energy will also be required to meet this increased demand. Such a mix is likely to include both unconventional fossil fuel resources – such as oil sands, coalbed methane and natural gas produced from shale formations – and renewable energy sources such as wind, biofuels and solar power. Beyond simply meeting growth in overall demand, a diverse mix would also help to provide enhanced national and global energy security while supporting the transition to a lower-carbon economy. Improving the efficiency of energy use will also play a key role in maintaining energy market balance in the future.

Along with increasing supply, we believe the energy industry will be required to make hydrocarbons cleaner and more efficient to use –particularly in the critical area of power generation, for which the key hydrocarbons are currently coal and gas. The world has reserves of coal for around 120 years at current consumption rates^b, but coal produces more carbon than any other fossil fuel. Carbon capture and storage (CCS) may help to provide a path to cleaner coal, and BP is investing in this area, but CCS technologies still face significant technical and economic issues and are unlikely to be in operation at scale for at least a decade.

          In contrast, we believe that in many countries natural gas has the potential to provide the most significant reductions in carbon emissions from power generation in the shortest time and at the lowest cost. These reductions can be achieved using technology available today. Combined- cycle turbines, fuelled by natural gas, produce around half the CO₂ emissions of coal-fired power, and are cheaper and quicker to build. It is estimated that there are reserves of natural gas in place equivalent to 60 years’ consumption at current rates^b and they are rising as new skills and technology unlock new unconventional gas resources. For these reasons, gas is looking to be an increasingly attractive resource in meeting the growing demand for energy, playing a greater role as a key part of the energy future.

          At the same time, alternative energies also have the potential to make a substantial contribution to the transition to a lower-carbon economy, but this will require investment, innovation and time. Currently, wind, solar, wave, tide and geothermal energy account for only around 1% of total global consumption^c. Even in the most aggressive scenario put forward by the IEA, these forms of energy are estimated to meet no more than 5% of total demand in 2030^d.

          If industry and the market are to meet the world’s growing demand for energy in a sustainable way, governments will be required to set a stable and enduring framework. As part of this, governments will need to provide secure access for exploration and development of fossil fuel resources, define mutual benefits for resource owners and development partners, and establish and maintain an appropriate legal and regulatory environment, including a mechanism for recognizing and incorporating the cost of reducing carbon emissions.

Our strategy

The priorities that drove our success in 2009 –safety, people and performance – remain the foundation of our agenda as we build on our momentum and work to further enhance our competitive position.

Our strategy is to invest competitively to grow oil and gas production while working to drive performance across the group through enhanced operating efficiency, capital efficiency and cost efficiency.

          To meet growing world demand, BP is committed to exploring, developing and producing more fossil fuel resources; manufacturing, processing and delivering better and more advanced products; and enabling the transition to a lower-carbon future. We aim to do this while operating safely, reliably and in compliance with the law. We strive to run our business within the discipline of a clear financial framework.

          In 2009, we improved our overall competitive performance by enhancing operating performance and reducing complexity and costs. We believe we can continue to compete successfully through our ability to access resources and deliver high-quality products and service to our customers. We intend to remain focused on the application of technology and developing relationships based on a commitment to long-term partnerships and mutual advantage. Our intention is to generate and sustain business momentum and growth through a rigorous process of continuous improvement and an ongoing focus on safety, people and performance.

Safety, reliability, compliance and continuous improvement

Safe, reliable and compliant operations remain the group’s first priority. A key enabler for this is the BP operating management system (OMS), which provides a common framework for all BP operations, designed to achieve consistency and continuous improvement in safety and efficiency. OMS includes mandatory practices, such as integrity management and incident investigation, which are designed to address particular risks. In addition, it enables each site to focus on the most important risks in its own operations and sets out procedures on how to manage them in accordance with the group-wide framework. Further information on our safety priorities and performance can be found on page 42.

The right people, skills and capability

It is vital that we develop and deploy people with the skills, capability and behaviours required to meet our objectives. Despite a tight global recruitment market for some of our core technical disciplines, we have been successful in building capacity and getting the right people with the right skills in the right place. We are now going further, strengthening the culture within BP through a commitment to continuous improvement in operations and enhancing the capabilities, technical expertise and organizational quality needed to drive performance.

          Our people strategy has already resulted in refreshed group leadership and senior management teams, recruitment focused on individuals with strong operational and technical expertise, and appropriate reward for performance at all levels.

Enhanced performance and efficiency

Our strategy aims to create value for shareholders by investing to deliver growth in our Exploration and Production business together with enhanced efficiency and high-quality earnings and returns throughout our operations.

          In Exploration and Production, our strategy is to invest to grow production safely, reliably and efficiently. We intend to achieve this by strengthening our portfolio of leadership positions in the world’s most prolific hydrocarbon basins, enabled by the development and application of technology and the building of strong relationships based on mutual advantage. We also intend to sustainably drive cost and capital efficiency in accessing, finding, developing and producing resources, enabled by deep technical capability and a culture of continuous improvement.

          In Refining and Marketing, our strategic focus is on enhancing portfolio quality, integrating activities across value chains and performance efficiency. We expect to continue building our business around advantaged assets in material and significant energy markets while improving the safety and reliability of our operations. Our objective is to achieve sector-leading levels of performance on a sustainable basis. To achieve this, we need to continue upgrading the manufacturing capabilities within our integrated fuels value chains to achieve the best capacity utilization and margin capture. We continue to explore appropriate opportunities to deploy downstream capital into faster-growing non-OECD markets. We also intend to continue our selective investment in our international businesses, which include petrochemicals and lubricants, where we see potential to deliver strong and sustainable returns.

          In Alternative Energy, we have focused our investments in the areas where we believe we can create the greatest competitive advantage. We have substantial businesses in wind and solar power and are developing advanced biofuels and low-carbon energy technologies such as hydrogen power and carbon capture and storage.

          Our determination to drive efficiency through our businesses has proved vital to our performance during a period of recession and we believe that it will remain critical to our future prospects as the global economy recovers and evolves.

Looking further ahead

As discussed in the ‘Our market’ section of this Annual Report on Form 20-F (see pages 7 to 9), we expect that the world will require a more diverse energy mix as the basis for a secure supply of energy over time. We intend to play a central role in meeting the world’s continued need for hydrocarbons, with our Exploration and Production and Refining and Marketing activities remaining at the core of our strategy. We are also creating long-term options for the future in new energy technology and low-carbon energy businesses. Current investment is focused on wind, solar and biofuels as potential sources of resource diversification for the world, and we are investing in carbon capture and storage as an enabling technology. We believe that this focused portfolio has the potential to be a material source of value creation for BP in the longer term (see pages 38 to 39). We are also enhancing our capabilities in natural gas, which is likely to play a greater role as a key part of the energy future. We intend to lead and shape this transition, including through the application of advanced technology to unlock sources of unconventional gas, while working to achieve sector-leading levels of return for our shareholders.

 

Our performance

2009 has been a successful year for BP, with positive financial and operational momentum despite an extremely turbulent global financial environment.

Safety

Good progress has been made on underpinning improved safety performance in 2009. Throughout the year, we continued to focus on training and enhancing procedures across the organization. Significantly, 2009 was an important year in the development of OMS. By the end of 2009, around 80% of our operating sites were using the system, including all our operated refineries and petrochemicals plants. (See Safety on page 42 for more information on OMS.)

           In 2009, a third-party-operated helicopter carrying contractors from BP’s Miller platform crashed in the North Sea, resulting in the tragic loss of 16 lives. In addition, BP sustained two fatalities within our own operations. We deeply regret the loss of these lives.

          Recordable injury frequency (RIF, a measure of the number of reported injuries per 200,000 hours worked) was 0.34, significantly below 2008 and 2007 levels of 0.43 and 0.48, respectively. Reported oil spills greater than one barrel were 234 in 2009 compared with 335 in 2008 and 340 in 2007. Our environmental measure that tracks greenhouse gas (GHG) emissions^a increased in 2009 to 65.0 million tonnes of carbon dioxide equivalent, compared with 61.4 million tonnes in 2008. The primary reason for this increase is the growth of our business, including the significant increase in our US refining throughputs, the start-up of our Tangguh LNG project in Indonesia and the continued success of our Gulf of Mexico deepwater operations, including Thunder Horse.

People

During 2009 we made further significant progress in generating a stronger performance focus and in fostering a culture that attributes more value to deep specialist skills and expertise. At the same time, we continued to improve operational efficiency and reduce overheads.

          Non-retail headcount was reduced by 4,400 (6%) in 2009. Overall, the number of employees (including retail staff) was reduced by 11,700 in 2009.

Performance

Against the backdrop of the global recession, we delivered a strong performance in 2009. Profit and cash flow were lower than in 2008, due primarily to a much weaker price environment, although the impact was partially offset by better operational performance and lower costs across the group as we implemented our efficiency programmes. Notable achievements include:

Exploration and Production

•		Replacing 129% of our proved reserves, on a combined basis of subsidiaries and equity-accounted entities.
•		Delivering a 5% underlying growth in productionb.
•		Reducing unit production costs by 12%.
•		Achieving a strong gas marketing and trading performance.
•		Accessing new resources in Egypt, the Gulf of Mexico, Indonesia, Iraq and Jordan.
•		Making the Tiber discovery in the Gulf of Mexico at a depth of over 35,000 feet, the deepest oil and gas discovery well ever drilled.
•		Making three further discoveries in Block 31, Angola.
•		Starting up Tangguh in Indonesia and six other major projects in the Gulf of Mexico, Trinidad and Russia.

Refining and Marketing

•		Restoring our overall performance so that it is once again competitive with our supermajor peers.
•		Achieving a Solomon refining availabilityc of 93.6%, which is an increase of almost five percentage points compared with 2008.
•		Reducing costs across the segment by more than 15%d.
•		Delivering a strong supply and trading performance.
•		Performing strongly in our international businesses, despite the weak environment.
•		Delivering simplification and lower costs through integration in the fuels value chains.
•		Simplifying the segment’s footprint in aviation and lubricants and completing the transfer of our US convenience retail business to a franchise operation.
•		Successfully exiting from our ground fuels marketing business in Greece.

This information, insofar as it relates to 2009, has been extracted or derived from the audited consolidated financial statements of the BP group presented on pages 107 to 182. Note 1 to the financial

statements includes details on the basis of preparation of these financial statements. The selected information should be read in conjunction with the audited financial statements and related notes elsewhere herein.

$ million except per share amounts
		2009				2008				2007				2006				2005
Income statement data
Sales and other operating revenues from continuing operationsa			239,272				361,143				284,365				265,906				239,792
Profit before interest and taxation from continuing operationsa			26,426				35,239				32,352				35,658				32,182
Profit from continuing operationsa			16,759				21,666				21,169				22,626				22,133
Profit for the year			16,759				21,666				21,169				22,601				22,317
Profit for the year attributable to BP shareholders			16,578				21,157				20,845				22,315				22,026
Capital expenditure and acquisitionsb			20,309				30,700				20,641				17,231				14,149
Per ordinary share – cents
Profit for the year attributable to BP shareholders
Basic			88.49				112.59				108.76				111.41				104.25
Diluted			87.54				111.56				107.84				110.56				103.05
Profit from continuing operations attributable to BP shareholdersa
Basic			88.49				112.59				108.76				111.54				103.38
Diluted			87.54				111.56				107.84				110.68				102.19
Dividends paid per share – cents			56.00				55.05				42.30				38.40				34.85
– pence			36.417				29.387				20.995				21.104				19.152
Ordinary share datac
Average number outstanding of 25 cent ordinary shares (shares million undiluted)			18,732				18,790				19,163				20,028				21,126
Average number outstanding of 25 cent ordinary shares (shares million diluted)			18,936				18,963				19,327				20,195				21,411
Balance sheet data
Total assets			235,968				228,238				236,076				217,601				206,914
Net assets			102,113				92,109				94,652				85,465				80,450
Share capital			5,179				5,176				5,237				5,385				5,185
BP shareholders’ equity			101,613				91,303				93,690				84,624				79,661
Finance debt due after more than one year			25,518				17,464				15,651				11,086				10,230
Net debt to net debt plus equityd			20%				21%				22%				20%				17%

 

Profits

Profit attributable to BP shareholders for the year ended 31 December 2009 was $16,578 million, including inventory holding gains, net of tax, of $2,623 million and a net charge for non-operating items, after tax, of $1,067 million. In addition, fair value accounting effects had a favourable impact, net of tax, of $445 million relative to management’s measure of performance. Inventory holding gains and losses, net of tax, are described in footnote (a) on page 49. More information on non-operating items and fair value accounting effects can be found on pages 54-55.

          Profit attributable to BP shareholders for the year ended 31 December 2008 was $21,157 million, including inventory holding losses, net of tax, of $4,436 million and a net charge for non-operating items, after tax, of $796 million. In addition, fair value accounting effects had a favourable impact, net of tax, of $146 million relative to management’s measure of performance.

Profit attributable to BP shareholders for the year ended 31 December 2007 was $20,845 million, including inventory holding gains, net of tax, of $2,475 million and a net charge for non-operating items, after tax, of $373 million. In addition, fair value accounting effects had an unfavourable impact, net of tax, of $198 million relative to management’s measure of performance.

          The primary additional factors affecting profit for 2009, compared with 2008, were lower realizations and refining margins, partly offset by higher production, stronger operational performance and lower costs.

          The primary additional factors reflected in profit for 2008, compared with 2007, were higher realizations, a higher contribution from the gas marketing and trading business, improved oil supply and trading performance, improved marketing performance and strong cost management; however, these positive effects were partly offset by weaker refining margins, particularly in the US, higher production taxes, higher depreciation, and adverse foreign exchange impacts.

 

Production and net proved oil and natural gas reserves

The following table shows our production for the past five years and the estimated net proved oil and natural gas reserves at the end of each of those years.

Production and net proved reserves^a

		2009f				2008				2007				2006				2005
Crude oil production for subsidiaries (thousand barrels per day)			1,400				1,263				1,304				1,351				1,423
Crude oil production for equity-accounted entities (thousand barrels per day)			1,135				1,138				1,110				1,124				1,139
Natural gas production for subsidiaries (million cubic feet per day)			7,450				7,277				7,222				7,412				7,512
Natural gas production for equity-accounted entities (million cubic feet per day)			1,035				1,057				921				1,005				912
Estimated net proved crude oil reserves for subsidiaries (million barrels)b			5,658				5,665				5,492				5,893				6,360
Estimated net proved crude oil reserves for equity-accounted entities (million barrels)c			4,853				4,688				4,581				3,888				3,205
Estimated net proved natural gas reserves for subsidiaries (billion cubic feet)d			40,388				40,005				41,130				42,168				44,448
Estimated net proved natural gas reserves for equity-accounted entities (billion cubic feet)e			4,742				5,203				3,770				3,763				3,856

a	Combined basis of subsidiaries and equity-accounted entities, on a basis consistent with general industry practice.
b	On 31 December 2008 the SEC published a revision of Rule 4-10 (a) of Regulation S-X for the estimation of reserves. These revised rules form the basis of the 2009 year-end estimation of proved reserves and the application of the technical aspects resulted in an immaterial increase of less than 1% to BP‘s total proved reserves.
c	Crude oil, condensate and natural gas liquids.

a	Natural gas is converted to oil equivalent at 5.8 billion cubic feet (bcf) = 1 million barrels.

Risk factors

We urge you to consider carefully the risks described below. If any of these risks occur, we might fail to deliver on our strategic priorities, which are expressed in terms of safety, people and performance (see page 10). Our business, financial condition and results of operations could suffer and the trading price and liquidity of our securities could decline.

In the current uncertain financial and economic environment, certain risks may gain more prominence either individually or when taken together. Oil and gas prices are likely to remain volatile with average prices and margins influenced by changes in supply and demand. This is likely to exacerbate competition in all businesses, which may impact costs and margins. At the same time, governments are facing greater pressure on public finances, which may increase their motivation to intervene in the fiscal and regulatory frameworks for the oil and gas industry, including the risk of increased taxation. The financial and economic situation may have a negative impact on third parties with whom we do, or may do, business. Any of these factors may affect our results of operations, financial condition and liquidity.

          Capital markets have regained some confidence after the recent crisis but if there are extended periods of constraints in these markets, at a time when cash flows from our business operations may be under pressure, our ability to maintain our long-term investment programme may be impacted with a consequent effect on our growth rate, and may impact shareholder returns, including dividends and share buybacks, or share price. Decreases in the funded levels of our pension plans may also increase our pension funding requirements.

          Our system of risk management identifies and provides the response to risks of group significance through the establishment of standards and other controls. Inability to identify, assess and respond to risks through this and other controls could lead to an inability to capture opportunities, threats materializing, inefficiency and non-compliance with laws and regulations.

          The risks are categorized against the following areas: strategic; compliance and control; and operational.

Access and renewal

Successful execution of our group plan depends critically on implementing activities to renew and reposition our portfolio. The challenges to renewal of our upstream portfolio are growing due to increasing competition for access to opportunities globally. Lack of material positions in new markets and/or inability to complete disposals could result in an inability to grow or even maintain our production.

Prices and markets

Oil, gas and product prices are subject to international supply and demand. Political developments and the outcome of meetings of OPEC can particularly affect world supply and oil prices. Previous oil price increases have resulted in increased fiscal take, cost inflation and more onerous terms for access to resources. As a result, increased oil prices may not improve margin performance. In addition to the adverse effect on revenues, margins and profitability from any fall in oil and natural gas prices, a prolonged period of low prices or other indicators would lead to

further reviews for impairment of the group’s oil and natural gas properties. Such reviews would reflect management’s view of long-term oil and natural gas prices and could result in a charge for impairment that could have a significant effect on the group’s results of operations in the period in which it occurs. Rapid material and/or sustained change in oil, gas and product prices can impact the validity of the assumptions on which strategic decisions are based and, as a result, the ensuing actions derived from those decisions may no longer be appropriate. A prolonged period of low oil prices may impact our ability to maintain our long-term investment programme with a consequent effect on our growth rate and may impact shareholder returns, including dividends and share buybacks, or share price. Periods of global recession could impact the demand for our products, the prices at which they can be sold and affect the viability of the markets in which we operate.

          Refining profitability can be volatile, with both periodic oversupply and supply tightness in various regional markets. Sectors of the chemicals industry are also subject to fluctuations in supply and demand within the petrochemicals market, with a consequent effect on prices and profitability.

Climate change and carbon pricing

Compliance with changes in laws, regulations and obligations relating to climate change could result in substantial capital expenditure, taxes, reduced profitability from changes in operating costs, and revenue generation and strategic growth opportunities being impacted. Our commitment to the transition to a lower-carbon economy may create expectations for our activities, and the level of participation in alternative energies carries reputational, economic and technology risks.

Socio-political

We have operations in countries where political, economic and social transition is taking place. Some countries have experienced political instability, changes to the regulatory environment, expropriation or nationalization of property, civil strife, strikes, acts of war and insurrections. Any of these conditions occurring could disrupt or terminate our operations, causing our development activities to be curtailed or terminated in these areas or our production to decline and could cause us to incur additional costs. In particular, our investments in Russia could be adversely affected by heightened political and economic environment risks.

          We set ourselves high standards of corporate citizenship and aspire to contribute to a better quality of life through the products and services we provide. If it is perceived that we are not respecting or advancing the economic and social progress of the communities in which we operate, our reputation and shareholder value could be damaged.

Competition

The oil, gas and petrochemicals industries are highly competitive. There is strong competition, both within the oil and gas industry and with other industries, in supplying the fuel needs of commerce, industry and the home. Competition puts pressure on product prices, affects oil products marketing and requires continuous management focus on reducing unit costs and improving efficiency. The implementation of group strategy requires continued technological advances and innovation including advances in exploration, production, refining, petrochemicals manufacturing technology and advances in technology related to energy usage. Our performance could be impeded if competitors developed or acquired intellectual property rights to technology that we required or if our innovation lagged the industry.

 

Investment efficiency

Our organic growth is dependent on creating a portfolio of quality options and investing in the best options. Ineffective investment selection could lead to loss of value and higher capital expenditure.

Reserves replacement

Successful execution of our group strategy depends critically on sustaining long-term reserves replacement. If upstream resources are not progressed in a timely and efficient manner, we will be unable to sustain long-term replacement of reserves.

Liquidity, financial capacity and financial exposure

The group has established a financial framework to ensure that it is able to maintain an appropriate level of liquidity and financial capacity and to constrain the level of assessed capital at risk for the purposes of positions taken in financial instruments. Failure to operate within our financial framework could lead to the group becoming financially distressed leading to a loss of shareholder value. Commercial credit risk is measured and controlled to determine the group’s total credit risk. Inability to determine adequately our credit exposure could lead to financial loss. A credit crisis affecting banks and other sectors of the economy could impact the ability of counterparties to meet their financial obligations to the group. It could also affect our ability to raise capital to fund growth.

          Crude oil prices are generally set in US dollars, while sales of refined products may be in a variety of currencies. Fluctuations in exchange rates can therefore give rise to foreign exchange exposures, with a consequent impact on underlying costs and revenues.

          For more information on financial instruments and financial risk factors see Financial statements — Note 24 on page 142.

Regulatory

The oil industry is subject to regulation and intervention by governments throughout the world in such matters as the award of exploration and production interests, the imposition of specific drilling obligations, environmental and health and safety protection controls, controls over the development and decommissioning of a field (including restrictions on production) and, possibly, nationalization, expropriation, cancellation or non-renewal of contract rights. We buy, sell and trade oil and gas products in certain regulated commodity markets. Failure to respond to changes in trading regulations could result in regulatory action and damage to our reputation. The oil industry is also subject to the payment of royalties and taxation, which tend to be high compared with those payable in respect of other commercial activities, and operates in certain tax jurisdictions that have a degree of uncertainty relating to the interpretation of, and changes to, tax law. As a result of new laws and regulations or other factors, we could be required to curtail or cease certain operations, or we could incur additional costs.

          For more information on environmental regulation, see Environment on pages 43-45.

Ethical misconduct and non-compliance

Our code of conduct, which applies to all employees, defines our commitment to integrity, compliance with all applicable legal requirements, high ethical standards and the behaviours and actions we expect of our businesses and people wherever we operate. Incidents of ethical misconduct or non-compliance with applicable laws and regulations could be damaging to our reputation and shareholder value. Multiple events of non-compliance could call into question the integrity of our operations.

          For certain legal proceedings involving the group, see Legal proceedings on pages 95-96.

Liabilities and provisions

Changes in the external environment, such as new laws and regulations, market volatility or other factors, could affect the adequacy of our provisions for pensions, tax, environmental and legal liabilities.

Reporting

External reporting of financial and non-financial data is reliant on the integrity of systems and people. Failure to report data accurately and in compliance with external standards could result in regulatory action, legal liability and damage to our reputation.

Process safety

Inherent in our operations are hazards that require continuous oversight and control. There are risks of technical integrity failure and loss of containment of hydrocarbons and other hazardous material at operating sites or pipelines. Failure to manage these risks could result in injury or loss of life, environmental damage, or loss of production and could result in regulatory action, legal liability and damage to our reputation.

Personal safety

Inability to provide safe environments for our workforce and the public could lead to injuries or loss of life and could result in regulatory action, legal liability and damage to our reputation.

Environmental

If we do not apply our resources to overcome the perceived trade-off between global access to energy and the protection or improvement of the natural environment, we could fail to live up to our aspirations of no or minimal damage to the environment and contributing to human progress. Failure to comply with environmental laws, regulations and permits could lead to damage to the environment and could result in regulatory action, legal liability and damage to our reputation.

Security

Security threats require continuous oversight and control. Acts of terrorism against our plants and offices, pipelines, transportation or computer systems could severely disrupt business and operations and could cause harm to people.

Product quality

Supplying customers with on-specification products is critical to maintaining our licence to operate and our reputation in the marketplace. Failure to meet product quality standards throughout the value chain could lead to harm to people and the environment and loss of customers.

Drilling and production

Exploration and production require high levels of investment and are subject to natural hazards and other uncertainties, including those relating to the physical characteristics of an oil or natural gas field. The cost of drilling, completing or operating wells is often uncertain. We may be required to curtail, delay or cancel drilling operations because of a variety of factors, including unexpected drilling conditions, pressure or irregularities in geological formations, equipment failures or accidents, adverse weather conditions and compliance with governmental requirements.

Transportation

All modes of transportation of hydrocarbons involve inherent risks. A loss of containment of hydrocarbons and other hazardous material could occur during transportation by road, rail, sea or pipeline. This is a significant risk due to the potential impact of a release on the environment and people and given the high volumes involved.

Major project delivery

Successful execution of our group plan depends critically on implementing the activities to deliver the major projects over the plan period. Poor delivery of any major project that underpins production growth and/or a major programme designed to enhance shareholder value could adversely affect our financial performance.

Digital infrastructure

The reliability and security of our digital infrastructure are critical to maintaining our business applications availability. A breach of our digital security could cause serious damage to business operations and, in some circumstances, could result in injury to people, damage to assets, harm to the environment and breaches of regulations.

Business continuity and disaster recovery

Contingency plans are required to continue or recover operations following a disruption or incident. Inability to restore or replace critical capacity to an agreed level within an agreed timeframe would prolong the impact of any disruption and could severely affect business and operations.

Crisis management

Crisis management plans and capability are essential to deal with emergencies at every level of our operations. If we do not respond or are perceived not to respond in an appropriate manner to either an external or internal crisis, our business and operations could be severely disrupted.

People and capability

Successful recruitment of new staff, employee training, development and long-term renewal of skills, in particular technical capabilities such as petroleum engineers and scientists, are key to implementing our plans. Inability to develop the human capacity and capability across the organization could jeopardize performance delivery.

Treasury and trading activities

In the normal course of business, we are subject to operational risk around our treasury and trading activities. Control of these activities is highly dependent on our ability to process, manage and monitor a large number of complex transactions across many markets and currencies. Shortcomings or failures in our systems, risk management methodology, internal control processes or people could lead to disruption of our business, financial loss, regulatory intervention or damage to our reputation.

Our systems of control

The board is responsible for the direction and oversight of BP. The board has set an overall goal for BP, which is to maximize long-term shareholder value through the allocation of its resources to activities in the oil, natural gas, petrochemicals and energy businesses. The board delegates authority for achieving this goal to the group chief executive (GCE).

          The board maintains five permanent committees that are composed entirely of non-executives. The board and its committees monitor, among other things, the identification and management of the group’s risks — both financial and non-financial. During the year, the board’s committees engaged with executive management, the general auditor and other monitoring and assurance providers (such as the group compliance and ethics officer and the external auditor) on a regular basis as part of their oversight of the group’s risks. Significant incidents that occurred and management’s response to them were considered by the appropriate committee and reported to the board. (See Board performance report on pages 65 to 76.)

          The GCE maintains a comprehensive system of internal control. This comprises the holistic set of management systems, organizational structures, processes, standards and behaviours that are employed to conduct our business and deliver returns for shareholders. The system is designed to meet the expectations of internal control of the Combined Code in the UK and of COSO (committee of the sponsoring organizations for the Treadway Commission) in the US. It addresses risks and how we should respond to them as well as the overall control environment. Each component of the system has been designed to respond to a particular type or collection of risks. Material risks are described within the Risk factors section (see pages 14 to 16).

          Key elements of our system of internal control are: the control environment; the management of risk and operational performance (including in relation to financial reporting); and the management of people and individual performance. Controls include the BP code of conduct, our leadership framework and our principles for delegation of authority, which are designed to make sure employees understand what is expected of them.

          As part of the control system, the GCE’s senior team — known as the executive team — is supported by sub-committees that are responsible for and monitor specific group risks. These include the group operations risk committee (GORC), the group financial risk committee (GFRC), the group people committee (GPC), and the group disclosures committee (GDC), which reviews the disclosures, controls and procedures over reporting.

          Operations and investments are conducted and reported in accordance with, and associated risks are thereby managed through, relevant standards and processes. These range from group standards, which set out processes for major areas such as safety and integrity, through to detailed administrative instructions on issues such as fraud reporting. The GCE conducts regular performance reviews with the segments and key functions to monitor performance and the management of risk and to intervene if necessary. People management is based on performance objectives, through which individuals are accountable for delivering specific elements of the group plan within agreed boundaries.

      

Forward-looking statements

In order to utilize the ‘Safe Harbor’ provisions of the United States Private Securities Litigation Reform Act of 1995, BP is providing the following cautionary statement. This document contains certain forward-looking statements with respect to the financial condition, results of operations and businesses of BP and certain of the plans and objectives of BP with respect to these items. These statements may generally, but not always, be identified by the use of words such as ‘will’, ‘expects’, ‘is expected to’, ‘aims’, ‘should’, ‘may’, ‘objective’, ‘is likely to’, ‘intends’, ‘believes’, ‘plans’, ‘we see’ or similar expressions. In particular, among other statements, (i) certain statements in Business review (pages 6-59), including under the headings ‘Outlook’, with regard to strategy, management aims and objectives, future capital expenditure, the future scrip dividend programme, future hydrocarbon production volume and the group’s ability to satisfy its long-term sales commitments from future supplies available to the group, date(s) or period(s) in which production is scheduled or expected to come onstream or a project or action is scheduled or expected to begin or be completed, capacity of planned plants or facilities and impact of health, safety and environmental regulations; (ii) the statements in Business review (pages 6-48) with regard to anticipated energy demand and consumption, global economic recovery, oil and gas prices, global reserves, expected future energy mix and the potential for cleaner and more efficient sources of energy, management aims and objectives, strategy, production, petrochemical and refining margins, anticipated investment in Alternative Energy, anticipated future project developments, growth of the international businesses, Refining and Marketing investments, reserves increases through technological developments, with regard to planned investment or other projects, timing and ability to complete announced transactions and future regulatory actions; and (iii) the statements in Business review (pages 49-59) with regard to the plans of the group, the cost of and provision for future remediation programmes and environmental operating and capital expenditures, taxation, liquidity and costs for providing pension and other post-retirement benefits; and including under ‘Liquidity and capital resources’ — Trend Information, with regard to global economic recovery, oil and gas prices, petrochemical and refining margins, production, demand for petrochemicals, production and production growth, depreciation, underlying average quarterly charge from Other businesses and corporate, costs, foreign exchange and energy costs, capital expenditure, timing and proceeds of divestments, balance of cash inflows and outflows, dividend and optional scrip dividend, cash flows, shareholder distributions, gearing, working capital, guarantees, expected payments under contractual and commercial commitments and purchase obligations; are all forward-looking in nature.

          By their nature, forward-looking statements involve risk and uncertainty because they relate to events and depend on circumstances that will or may occur in the future and are outside the control of BP. Actual results may differ materially from those expressed in such statements, depending on a variety of factors, including the specific factors identified in the discussions accompanying such forward-looking statements; the timing of bringing new fields onstream; future levels of industry product supply, demand and pricing; operational problems; general economic conditions; political stability and economic growth in relevant areas of the world; changes in laws and governmental regulations; actions by regulators; exchange rate fluctuations; development and use of new technology; the success or otherwise of partnering; the actions of competitors; natural disasters and adverse weather conditions; changes in public expectations and other changes to business conditions; wars and acts of terrorism or sabotage; and other factors discussed elsewhere in this report including under ‘Risk factors’ on pages 14-16. In addition to factors set forth elsewhere in this report, those set out above are important factors, although not exhaustive, that may cause actual results and developments to differ materially from those expressed or implied by these forward-looking statements.

Statements regarding
competitive position

Statements referring to BP’s competitive position are based on the company’s belief and, in some cases, rely on a range of sources, including investment analysts’ reports, independent market studies and BP’s internal assessments of market share based on publicly available information about the financial results and performance of market participants.

Further note on certain activities

During the period covered by this report, non-US subsidiaries or other non-US entities of BP, conducted limited activities in, or with persons from, certain countries identified by the US Department of State as State Sponsors of Terrorism (‘Sanctioned Countries’). These activities continue to be insignificant to the group’s financial condition and results of operations.

          BP has interests in, and is the operator of, two fields and a pipeline located outside Iran in which the National Iranian Oil Company (NIOC) and an affiliated entity have interests. BP buys crude oil, refinery and petrochemicals feedstocks, blending components and LPG of Iranian origin or from Iranian counterparties primarily for sale to third parties in Europe and a small portion is used by BP in its own facilities in South Africa and Europe. Until recently BP held an equity interest in an Iranian joint venture that has a blending facility and markets lubricants for sale to domestic consumers. In January 2010, BP restructured its interest in the joint venture and currently maintains its involvement through certain contractual arrangements, which it keeps under review in light of pending legislative developments in the US. BP does not seek to obtain from the government of Iran licences or agreements for oil and gas projects in Iran, is not conducting any technical studies in Iran and does not own or operate any refineries or petrochemicals plants in Iran.

          BP sells lubricants in Cuba through a 50:50 joint venture there and in 2009 purchased a cargo of naphtha from a non-Cuban counterparty that was loaded in Cuba. In Syria, lubricants are sold through a distributor and BP obtains crude oil and refinery feedstocks for sale to third parties in Europe. In addition, BP sells crude oil and refined products into Syria.

          BP supplies fuels and lubricants to airlines and shipping companies from Sanctioned Countries at airports and ports located outside these countries.

          BP monitors its activities with Sanctioned Countries and keeps them under review to ensure compliance with applicable laws and regulations of the US and other countries where BP operates.

 

 

Exploration and Production

Our Exploration and Production segment includes upstream and midstream activities in 30 countries, including Angola, Azerbaijan, Canada, Egypt, Russia, Trinidad & Tobago (Trinidad), Norway, the UK, the US and locations within Asia Pacific, Latin America, North Africa and the Middle East, as well as gas marketing and trading activities, primarily in Canada, Europe and the US. Upstream activities involve oil and natural gas exploration and field development and production. Our exploration programme is currently focused around Angola, Egypt, the deepwater Gulf of Mexico, Libya, the North Sea, Oman and onshore US. Major development areas include Algeria, Angola, Asia Pacific, Azerbaijan, Egypt and the deepwater Gulf of Mexico. During 2009, production came from 21 countries. The principal areas of production are Angola, Asia Pacific, Azerbaijan, Egypt, Latin America, the Middle East, Russia, Trinidad, the UK and the US.

          Midstream activities involve the ownership and management of crude oil and natural gas pipelines, processing facilities and export terminals, LNG processing facilities and transportation, and our NGL extraction businesses in the US, the UK, Canada and Indonesia. Our most significant midstream pipeline interests are the Trans-Alaska Pipeline System in the US, the Forties Pipeline System and the Central Area Transmission System pipeline, both in the UK sector of the North Sea, the South Caucasus Pipeline (SCP), which takes gas from Azerbaijan through Georgia to the Turkish border and the Baku-Tbilisi-Ceyhan pipeline, running through Azerbaijan, Georgia and Turkey. Major LNG activities are located in Trinidad, Indonesia and Australia. BP is also investing in the LNG business in Angola.

          Additionally, our activities include the marketing and trading of natural gas, power and natural gas liquids. These activities provide routes into liquid markets for BP’s gas and power, and generate margins and fees associated with the provision of physical and financial products to third parties and additional income from asset optimization and trading.

          Our oil and natural gas production assets are located onshore and offshore and include wells, gathering centres, in-field flow lines, processing facilities, storage facilities, offshore platforms, export systems (e.g. transit lines), pipelines and LNG plant facilities.

          Upstream operations in Argentina, Bolivia, Chile, Abu Dhabi, Kazakhstan, Venezuela and Russia, as well as some of our operations in Angola, Canada and Indonesia, are conducted through equity-accounted entities.

The market environment in which we operate was particularly challenging during 2009, with crude oil and natural gas prices at lower levels than we have experienced in recent history.

          The annual average crude oil price declined in 2009 for the first time since 2001, breaking an unprecedented string of seven consecutive annual increases. Dated Brent for the year averaged $61.67 per barrel, about 37% below 2008’s record average of $97.26 per barrel. Prices were lowest at the beginning of the year as the world economy grappled with the sharpest downturn in modern economic history.

          In 2010, we expect oil market movements to continue to be driven by developments in the world economy, by their resulting implications for oil consumption, and by OPEC production decisions.

          Natural gas prices weakened in 2009 and were volatile. The average US Henry Hub First of Month Index fell to $3.99/mmBtu in 2009, a 56% decrease from the record $9.04/mmBtu average seen in 2008.

Recession-induced demand declines and strong production caused prices to drop from $6.16/mmBtu at the start of the year to $2.84/mmBtu in September. However, over the course of the year, the impact was partly offset as US regional gas price differentials narrowed, driven partly by the Rockies Express Pipeline extension allowing the transportation of larger quantities of gas out of the Rockies area. Reduced imports from Canada, slowing US production growth and cooler temperatures allowed prices to recover to $4.49/mmBtu by the end of the year. Prices at the UK National Balancing Point similarly fell to an average of 30.85 pence per therm, 47% below the 2008 average price of 58.12 pence per therm.

          In 2009, there was a switch of uncontracted LNG cargoes from Asia to Europe, reflecting a shift in relative spot prices. LNG imports to Europe have competed with pipeline imports, where the gas price is often indexed to oil prices, as well as with marginal European gas production. On an energy equivalent basis, gas prices were often at or below parity with coal, which led to gas displacing coal in power generation in Europe and the US.

          In the event of any recovery in the economy in 2010, both the US and UK gas markets are expected to benefit although the price upside is likely to be constrained as a result of a record amount of LNG expected to become available globally.

Our strategy is to invest to grow production safely, reliably and efficiently by:

•		Strengthening our portfolio of leadership positions in the world’s most prolific hydrocarbon basins, enabled by the development and application of technology and strong relationships based on mutual advantage.
•		Sustainably driving cost and capital efficiency in accessing, finding, developing and producing resources, enabled by deep technical capability and a culture of continuous improvement.

In Exploration and Production, safety, both personal and process, remains our highest priority. 2009 brought further improvements in personal safety with our reported recordable injury frequency improving from 0.43 in 2008 to 0.39 in 2009. We also achieved improvements in the number of reported process safety-related incidents and a significant reduction in the number of reported spills.

          BP’s operating management system (OMS) provides us with a systematic framework for safe, reliable and efficient operations. Throughout 2009, OMS helped us to deliver continuous improvement in the way we manage our people, processes, plant and performance.

          From onshore production facilities to offshore platforms, a total of 47 exploration and production sites had completed their transition to OMS by the end of 2009. The remaining seven sites are on track to transition to OMS in 2010.

      

We continually seek to access resources and in 2009 this included Iraq, where, together with China National Petroleum Corporation (CNPC), we entered into a contract with the state-owned South Oil Company (SOC) to expand production from the Rumaila field; Jordan, where on 3 January 2010, we received approval from the Government of Jordan to join the state-owned National Petroleum Company (NPC) to exploit the onshore Risha concession in the north east of the country; further access in Egypt, where we were awarded two blocks in an offshore area of the Nile Delta; Indonesia, where we signed a production-sharing agreement (PSA) for the exploration and development of coalbed methane in the Sanga-Sanga block, supplying gas to Indonesia’s largest LNG export facility and, subject to Government of Indonesia approval, farmed into Chevron’s West Papua I & III blocks; and the Gulf of Mexico, where we were awarded 61 blocks through the Outer Continental Shelf Lease Sales 208 and 210.

          In 2009, we were involved in a number of discoveries. The most significant of these were in the deepwater Gulf of Mexico with the Tiber well; Angola, where we made three further discoveries in the ultra deepwater Block 31; and Canada, where we discovered natural gas with the Ellice J27 well.

          Seven major projects came onstream. We continue to grow our position and leverage our experience as the largest producer in the Gulf of Mexico, starting up three projects ahead of schedule, including the second phase of Atlantis. In addition, production commenced at our Savonette field in Trinidad, at our Tangguh LNG project in Indonesia and, through TNK-BP, we saw the start-up of a further two projects, in the northern hub of Kamennoye, and the Urna and Ust-Tegus fields in the Uvat area.

          Production from our established centres — including the North Sea, Alaska, North America Gas and Trinidad — was on plan, with improved operating efficiency for the segment as a whole, and we had strong production growth in the Gulf of Mexico, including excellent performance from Thunder Horse. Production from Egypt and TNK-BP also made a strong contribution to our growth.

          Production for the year was up more than 4% from last year. After adjusting for the effect of entitlement changes in our PSAs and the effect of OPEC quota restrictions, underlying production growth^a was 5% higher than 2008.

We also reduced unit production costs through a combination of high-grading activity, improving execution efficiency, capturing the benefits of the deflationary cost environment at the beginning of the year and favourable foreign exchange effects. During 2009 we improved the quality of our procurement and supply chain management organization, systems and processes, which we expect will help deliver sustained cost efficiency in the future.

          The replacement cost profit before interest and tax was $24.8 billion, a 35% decrease compared with the record level in 2008. This result was primarily driven by lower oil and gas realizations, lower income from equity-accounted entities and higher depreciation, partly offset by strong underlying production growth and improved cost management, which contributed to a 12% reduction in unit production costs. Our financial results are discussed in more detail on pages 51-52.

          Total capital expenditure including acquisitions and asset exchanges in 2009 was $14.9 billion (2008 $22.2 billion and 2007 $14.2 billion). In 2009, capital expenditure included $306 million relating to the award of the contract to redevelop the Rumaila field in Iraq.

          Development expenditure of subsidiaries incurred in 2009, excluding midstream activities, was $10,396 million, compared with $11,767 million in 2008 and $10,153 million in 2007.

$ million
		2009				2008				2007
Sales and other operating revenuesa			57,626				86,170				65,740
Replacement cost profit before interest and taxb			24,800				38,308				27,602
Total assets			140,149				136,665				125,736
Capital expenditure and acquisitions			14,896				22,227				14,207
$  per barrel
Average BP liquids realizationsc d			56.26				90.20				67.45
$  per thousand cubic feet
Average BP natural gas realizationsc			3.25				6.00				4.53

The table below presents our average sales price per unit of production.

		$ per unit of productiona
		┌───────Europe───────┐								┌───────North───────┐								┌─South─┐				┌─Africa─┐				┌───────Asia───────┐								┌Australasia┐				Total group
										America								America																				average
														Rest of
						Rest of								North																Rest of
		UK				Europe				US				America												Russia				Asia
Average sales priceb
2009
Liquidsc			62.19				60.73				53.68				30.77				52.48				57.40				—				61.27				57.22				56.26
Gas			4.68				7.62				3.07				3.53				2.50				3.61				—				3.30				5.25				3.25
2008
Liquidsc			89.82				93.77				89.22				64.42				91.61				89.44				—				97.20				86.33				90.20
Gas			8.41				6.96				6.77				7.87				4.90				4.46				—				3.63				9.22				6.00
2007
Liquidsc			69.17				70.41				64.18				48.24				65.54				67.81				—				73.00				70.56				67.45
Gas			6.40				5.84				5.43				6.24				3.25				3.93				—				3.05				5.96				4.53

      

The table below presents our average production cost per unit of production.

		$ per unit of productiona
		┌───────Europe───────┐								┌───────North───────┐								┌─South─┐				┌─Africa─┐				┌───────Asia───────┐								┌Australasia┐				Total group
										America								America																				average
														Rest of
						Rest of								North																Rest of
		UK				Europe				US				America												Russia				Asia
The average production cost per unit of productiona
2009			12.38				10.72				7.26				14.45				2.20				6.05				—				4.35				1.60				6.39
2008			12.19				8.74				9.02				15.35				2.34				6.72				—				5.24				1.74				7.24
2007			14.00				7.17				9.03				14.04				2.69				6.43				—				3.81				1.75				7.14

      

BP bases its proved reserves estimates on the requirement of reasonable certainty with rigorous technical and commercial assessments based on conventional industry practice. BP only applies technologies that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. BP applies high resolution seismic data for the identification of reservoir extent and fluid contacts only where there is an overwhelming track record of success in its local application. In certain deepwater fields, such as fields in the Gulf of Mexico, BP has booked proved reserves before production flow tests are conducted, in part because of the significant safety, cost and environmental implications of conducting these tests. The industry has made substantial technological improvements in understanding, measuring and delineating reservoir properties without the need for flow tests. To determine reasonable certainty of commercial recovery, BP employs a general method of reserves assessment that relies on the integration of three types of data: (1) well data used to assess the local characteristics and conditions of reservoirs and fluids; (2) field scale seismic data to allow the interpolation and extrapolation of these characteristics outside the immediate area of the local well control; and (3) data from relevant analogous fields. Well data includes appraisal wells or sidetrack holes, full logging suites, core data and fluid samples. BP considers the integration of this data in certain cases to be superior to a flow test in providing understanding of overall reservoir performance. The collection of data from logs, cores, wireline formation testers, pressures and fluid samples calibrated to each other and to the seismic data can allow reservoir properties to be determined over a greater volume than the localized volume of investigation associated with a short-term flow test. There is a strong track record of proved reserves recorded using these methods, validated by actual production levels.

Governance

BP’s centrally controlled process for proved reserves estimation approval forms part of a holistic and integrated system of internal control. It consists of the following elements:

•		Accountabilities of certain officers of the group to ensure that there is review and approval of proved reserves bookings independent of the operating business and that there are effective controls in the approval process and verification that the proved reserves estimates and the related financial impacts are reported in a timely manner.
•		Capital allocation processes, whereby delegated authority is exercised to commit to capital projects that are consistent with the delivery of the group’s business plan. A formal review process exists to ensure that both technical and commercial criteria are met prior to the commitment of capital to projects.
•		Internal Audit, whose role includes systematically examining the effectiveness of the group’s financial controls designed to assure the reliability of reporting and safeguarding of assets and examining the group’s compliance with laws, regulations and internal standards.
•		Approval hierarchy, whereby proved reserves changes above certain threshold volumes require central authorization and periodic reviews. The frequency of review is determined according to field size and ensures that more than 80% of the BP proved reserves base undergoes central review every two years and more than 90% is reviewed centrally every four years.

BP’s segment resources authority is the petroleum engineer primarily responsible for overseeing the preparation of the reserves estimate. He has over 35 years of diversified industry experience with the past 10 spent as the head of the reservoir management function within BP. He is a member of the Society of Petroleum Engineers (SPE) and the Institute of Materials, Minerals and Mining. On the retirement of the current

segment resources authority in 2010, his responsibilities for reserves estimation, governance and compliance will be taken by the current vice president of segment reserves. The current vice president of segment reserves has over 25 years of diversified industry experience with the past seven spent managing the governance and compliance of BP’s reserves estimation. He is a sitting member of the SPE Oil and Gas Reserves Committee and the United Nations Economic Commission for Europe Expert Group on Resource Classification.

          For the executive directors and senior management, no specific portion of compensation bonuses is directly related to proved reserves targets. Additions to proved reserves is one of several indicators by which the performance of the Exploration and Production segment is assessed by the remuneration committee for the purposes of determining compensation bonuses for the executive directors. Other indicators include a number of financial and operational measures.

          BP’s variable pay programme for the other senior managers in the Exploration and Production segment is based on individual performance contracts. Individual performance contracts are based on agreed items from the business performance plan, one of which, if chosen, could relate to proved reserves.

Proved reserves replacement

Total hydrocarbon proved reserves, on an oil equivalent basis including equity-accounted entities, comprised 18,292mmboe (12,621mmboe for subsidiaries and 5,671mmboe for equity-accounted entities) at 31 December 2009, an increase of 0.8% (increase of 0.5% for subsidiaries and increase of 1.5% for equity-accounted entities) compared with 31 December 2008. Natural gas represents about 43% (55% for subsidiaries and 14% for equity-accounted entities) of these reserves. The increase includes a net decrease from acquisitions and divestments of 282mmboe, (59mmboe net decrease for subsidiaries and 223mmboe net decrease for equity-accounted entities) largely comprising a number of assets in Bolivia, Indonesia, Kazakhstan, Pakistan and the UK.

          The proved reserves replacement ratio is the extent to which production is replaced by proved reserves additions. This ratio is expressed in oil equivalent terms and includes changes resulting from revisions to previous estimates, improved recovery and extensions and discoveries, and may be expressed as a replacement ratio excluding acquisitions and divestments or as a total replacement ratio including acquisitions and divestments. For 2009 the proved reserves replacement ratio excluding acquisitions and divestments was 129% (121% in 2008 and 112% in 2007) for subsidiaries and equity-accounted entities, 112% for subsidiaries alone and 164% for equity-accounted entities alone.

          In 2009, net additions to the group’s proved reserves (excluding production, sales and purchases of reserves-in-place and equity-accounted entities) amounted to 1,113mmboe (795mmboe for equity-accounted entities), principally through improved recovery from, and extensions to, existing fields and discoveries of new fields. Of our subsidiary reserves additions through improved recovery from, and extensions to, existing fields and discoveries of new fields, approximately 55% are associated with new projects and are proved undeveloped reserves additions. Volumes added in 2009 principally relied on the application of conventional technologies. The remaining additions are in existing developments where they represent a mixture of proved developed and proved undeveloped reserves. The principal reserves additions in our subsidiaries were in the US (Arkoma, Mad Dog, Prudhoe Bay, Thunder Horse), the UK (Clair), Trinidad (Kapok), Angola (Pazflor) and Australia (Jansz-Io). The principal reserves additions in our equity-accounted entities were in Argentina (Cerro Dragon, Cuenca Marina Austral) and in Russia (Kamennoye, Samatlor).

Compliance

International Financial Reporting Standards (IFRSs) do not provide specific guidance on reserves disclosures. BP estimates proved reserves in accordance with SEC Rule 4-10 (a) of Regulation S-X and relevant Compliance and Disclosure Interpretations (C&DI) and Staff Accounting Bulletins as issued by the SEC staff. On 31 December 2008, the SEC published a revision of Rule 4-10 (a) of Regulation S-X for the estimation of reserves. These revised rules form the basis of the 2009 year-end estimation of proved reserves and the application of the technical aspects resulted in an immaterial increase of less than 1% to BP’s total proved reserves. The reasons for the increase are primarily due to the application of reliable technologies and inclusion of proved reserves more than one spacing away from existing penetrations as discussed below.

          By their nature, there is always some risk involved in the ultimate development and production of proved reserves, including, but not limited to, final regulatory approval, the installation of new or additional infrastructure as well as changes in oil and gas prices, changes in operating and development costs and the continued availability of additional development capital. All the group’s proved reserves held in subsidiaries and equity-accounted entities are estimated by the group’s petroleum engineers.

          Our proved reserves are associated with both concessions (tax and royalty arrangements) and agreements where the group is exposed to the upstream risks and rewards of ownership, but where title to the hydrocarbons is not conferred, such as PSAs. In a concession, the consortium of which we are a part is entitled to the proved reserves that can be produced over the licence period, which may be the life of the field. In a PSA, we are entitled to recover volumes that equate to costs incurred to develop and produce the proved reserves and an agreed share of the remaining volumes or the economic equivalent. As part of our entitlement is driven by the monetary amount of costs to be recovered, price fluctuations will have an impact on both production volumes and reserves. Fourteen percent of our proved reserves are associated with PSAs. The main countries in which we operate under PSAs are Algeria, Angola, Azerbaijan, Egypt, Indonesia and Vietnam.

          We disclose our share of proved reserves held in equity-accounted entities (jointly controlled entities and associates), although we do not control these entities or the assets held by such entities.

Our total hydrocarbon production during 2009 averaged 3,998 thousand barrels of oil equivalent per day (mboe/d). This comprised 2,684mboe/d for subsidiaries and 1,314mboe/d for equity-accounted entities, an increase of 6.6% and a decrease of 0.5% respectively compared with 2008. For subsidiaries, 40% of our production was in the US, 17% in Trinidad and 10% in the UK. For equity-accounted entities, 71% of production was from Russia, 14% in the United Arab Emirates and 11% in Argentina.

          The strong growth in production in 2009 benefited by about 40mboe/d on an annual basis from a combination of the absence of a significant hurricane season and from the make-up of a prior period underlift. As a result, we expect production in 2010 to be slightly lower than in 2009. The actual growth rate will depend on a number of factors, including our pace of capital spending, the efficiency of that spend, the oil price and its impact on PSAs, as well as OPEC quota restrictions.

          The group and its equity-accounted entities have numerous long-term sales commitments in their various business activities, all of which are expected to be sourced from supplies available to the group which are not subject to priorities, curtailments or other restrictions. No single contract or group of related contracts is material to the group.

The following tables show BP’s estimated net proved reserves as at 31 December 2009.

million barrels
		Developed				Undeveloped				Total
UK			403				291				694
Rest of Europe			83				184				267
US			1,862				1,211				3,073	c
Rest of North America			11				1				12
South America			49				56				105	d
Africa			422				454				876
Rest of Asia			182				334				516
Australasia			58				57				115
Subsidiaries			3,070				2,588				5,658
Equity-accounted entities			3,121				1,732				4,853	e
Total			6,191				4,320				10,511

billion cubic feet
		Developed				Undeveloped				Total
UK			1,602				670				2,272
Rest of Europe			49				397				446
US			9,583				5,633				15,216
Rest of North America			716				453				1,169
South America			3,177				7,393				10,570	f
Africa			1,107				1,454				2,561
Rest of Asia			1,579				249				1,828
Australasia			3,219				3,107				6,326
Subsidiaries			21,032				19,356				40,388
Equity-accounted entities			3,035				1,707				4,742	g
Total			24,067				21,063				45,130

million barrels of oil equivalent
		Developed				Undeveloped				Total
Subsidiaries			6,696				5,925				12,621
Equity-accounted entities			3,644				2,027				5,671
Total			10,340				7,952				18,292

      

The following tables show BP’s net production by major field for 2009, 2008 and 2007.

thousand barrels per day
				BP net share of production										a
		Field or area		2009				2008				2007
UKb		ETAPc			34				27				32
		Foinavend			29				26				37
		Other			105				120				132
Total UK					168				173				201
Norway		Various			40				43				51
Total Rest of Europe					40				43				51
Total Europe					208				216				252
Alaska		Prudhoe Bayd			69				72				74
		Kuparuk			45				48				52
		Milne Pointd			24				27				28
		Other			43				50				55
Total Alaska					181				197				209
Lower 48 onshoreb		Various			97				97				108
Gulf of Mexico deepwater		Thunder Horsed			133				24				—
		Atlantisd			54				42				2
		Mad Dogd			35				31				25
		Mars			29				28				30
		Na Kikad			27				29				32
		Horn Mountaind			25				18				18
		Kingd			22				23				22
		Other			62				49				67
Total Gulf of Mexico deepwater					387				244				196
Total US					665				538				513
Canadab		Variousd			8				9				8
Total Rest of North America					8				9				8
Total North America					673				547				521
Colombia		Variousd			23				24				28
Trinidad & Tobago		Variousd			38				38				30
Venezuelab		Various			—				4				16
Total South America					61				66				74
Angola		Greater Plutoniod			70				69				12
		Kizomba C Dev			43				30				—
		Dalia			32				34				31
		Girassol FPSO			22				22				20
		Other			44				46				77
Total Angola					211				201				140
Egypt		Gupco			55				41				36
		Other			16				16				7
Total Egypt					71				57				43
Algeria		Various			22				19				12
Total Africa					304				277				195
Azerbaijan		Azeri-Chirag-Gunashlid			94				97				200
		Other			7				8				5
Total Azerbaijan					101				105				205
Western Indonesiab		Various			5				7				7
Other		Various			17				16				16
Total Rest of Asiab					123				128				228
Total Asia					123				128				228
Australia		Various			31				29				34
Total Australasia					31				29				34
Total subsidiariese					1,400				1,263				1,304
Equity-accounted entities (BP share)
Russia — TNK-BPb		Various			840				826				832
Total Russia					840				826				832
Abu Dhabif		Various			182				210				192
Other		Various			12				10				9
Total Rest of Asiab					194				220				201
Total Asia					1,034				1,046				1,033
Argentina		Various			75				70				69
Venezuelab		Various			25				19				6
Boliviab		Various			1				3				2
Total South America					101				92				77
Total equity-accounted entities					1,135				1,138				1,110
Total subsidiaries and equity-accounted entities					2,535				2,401				2,414

								million cubic feet per day
				BP net share of production										a
		Field or area		2009				2008				2007
UKb		Bruce/Rhumc			110				165				161
		Brae East			62				71				60
		Other			446				523				547
Total UK					618				759				768
Netherlandsb		Various			—				—				3
Norway		Various			16				23				26
Total Rest of Europe					16				23				29
Total Europe					634				782				797
Lower 48 onshoreb		San Juanc			659				682				694
		Jonahc			227				221				173
		Arkomac			194				240				204
		Wamsutterc			146				136				120
		Hugotonc			102				91				123
		Tuscaloosac			65				65				78
		Other			562				451				458
Total Lower 48 onshore					1,955				1,886				1,850
Gulf of Mexico deepwater		Thunder Horsec			83				11				—
		Other			220				219				269
Total Gulf of Mexico deepwater					303				230				269
Alaska		Various			58				41				55
Total US					2,316				2,157				2,174
Canadab		West Central			69				63				63
		Otherc			194				182				192
Total Canada					263				245				255
Total Rest of North America					263				245				255
Total North America					2,579				2,402				2,429
Trinidad & Tobago		Mangoc			664				471				22
		Cashima/NEQBc			571				375				6
		Kapokc			540				619				984
		Cannonballc			225				336				628
		Amherstiac			197				288				155
		Otherc			233				357				638
Total Trinidad					2,430				2,446				2,433
Colombia		Various			62				84				104
Venezuelab		Various			—				2				6
Total South America					2,492				2,532				2,543
Egypt		Temsah			118				109				118
		Ha’pyc			94				94				108
		Taurtc			73				24				—
		Other			177				145				89
Total Egypt					462				372				315
Algeria		Various			159				112				153
Total Africa					621				484				468
Pakistanb		Variousc			173				162				121
Azerbaijan		Variousc			126				143				73
Western Indonesiab		Sanga-Sanga			71				69				75
		Other			35				97				81
Total Western Indonesia					106				166				156
China		Yacheng			83				91				85
Vietnam		Variousc			63				61				82
Sharjah		Variousc			59				73				92
Total Rest of Asia					610				696				609
Total Asia					610				696				609
Australia		Perseus/Athena			142				229				193
		Goodwyn			139				74				107
		Angel			120				6				—
		Other			39				71				76
Total Australia					440				380				376
Eastern Indonesia		Tangguhc			74				1				—
Total Australasia					514				381				376
Total subsidiariesd					7,450				7,277				7,222
Equity-accounted entities (BP share)
Russia — TNK-BPb		Various			601				564				451
Total Russia					601				564				451
Western Indonesia		Various			31				31				33
Kazakhstanb		Various			11				8				8
Total Rest of Asia					42				39				41
Total Asia					643				603				492
Argentina		Various			378				385				369
Boliviab		Various			11				63				60
Venezuelab		Various			3				6				—
Total South America					392				454				429
Total equity-accounted entitiesd					1,035				1,057				921
Total subsidiaries and equity-accounted entities					8,485				8,334				8,143